As petroleum reservoirs and their available reservoir pressures deplete, oil and gas wells require an artificial lift solution to efficiently produce production fluids to surface. In many cases, wells have insufficient energy upon initial completion and require artificial lifting solutions immediately after the well is put on stream.
Low pressure producing wells are highly sensitive to back pressure being applied against the formation. As such, the lifting solution is required to operate efficiently with a minimal liquid head and static gas pressure applying a small nominal back pressure against the producing zone. The low nominal required back pressure against the formation during production implies that the pumping unit must be landed as close to the producing formation as possible. The smallest vertical distance possible is ideal; however herein lies the challenge for the existing pumping devices since in order to minimize the vertical distance between the pump intake and reservoir, the pump must be landed at or near 90 degree inclination from vertical. At any inclination greater than approximately 45 degrees, existing rod pumping devices are highly inefficient.
The operation of a conventional rod pump is cyclic. When the traveling valve is positioned at the bottom of the pump barrel, immediately above the closed barrel cage, the pump is at the bottom of its downstroke. At this point, the plunger and pump barrel above the traveling valve are full with produced fluid. As the rod moves up, it carries the traveling valve upwards with it, which isolates the hydrostatic pressure above the traveling valve from the region between the traveling valve and the standing valve. The upward movement of the traveling valve creates a low pressure region between the traveling and standing valves. The reservoir pressure from below the standing valve then unseats the standing valve, and fluid from the formation enters the pump barrel through the standing valve. The fluid above the traveling valve is carried through the pump barrel and upwards towards the surface during the upward movement of the valve rod. The pump then reaches the top of its upstroke. From there, the traveling valve descends through the fluid which just entered the pump barrel, trapped between the traveling and standing valves. The fluids in the barrel unseat the traveling valve as it travels downward to permit transfer of the fluid from the pump barrel below the traveling valve to the pump barrel above the traveling valve. Finally, the traveling valve moves to the bottom of the pump barrel to complete the rod pump stroke.
The high degree of inefficiency of the rod pumping system at greater inclinations is a result of the traditional rod pump valve configurations. Conventional gravity assisted, vertically oriented rod pump systems employ a ball and seat valve configuration in which the components are matched pairs, which is accomplished by lapping of the two surfaces. Variations of this standard configuration exist including hemispherical, guided valve, and matched and lapped seats as described in U.S. Pat. No. 5,829,952. This style of valve is highly dependent on gravity to return the ball (or other valve element) to the seat and isolate the top side of the valve from the region below the valve. As a result, traditional rod pumping systems have been conventionally described as gravity assisted and requiring an orientation at or near vertical for efficient operation.
When the inclination of the rod pump is greater than about 45° from vertical, the ball may not return to the seat but instead will reside off seat lying against the wall of the closed cage in the rod pumping system. When this occurs, the valves fail to isolate the tubing hydrostatic pressure from the reservoir/wellbore pressure, and do not positively displace the fluid into the production tubing. This is often mistaken at surface as worn pump valves or plunger components, gas interference or simply taken as “normal operating” conditions for these systems. Therefore, the most frequent response to these conditions at surface is to reciprocate the rod pump at a higher frequency by speeding up the pump jack, in an effort to seat the valves using kinetic force. At best, this will moderately improve the pumping performance.
The implications of this operating strategy result not only in poor pumping efficiency, but also accelerated tubing and rod wear, higher maintenance costs for surface equipment (belts, gearboxes, drive motors, etc.), higher horsepower and fuel costs, and shorter than expected rod pump life.
If the produced fluid has increased gas-liquid ratio, which has inherently higher compressibility than liquid alone, additional complications may arise. This compressibility will often not allow sufficient pressure to build in the barrel or the rod pump during the downstroke to overcome the hydrostatic pressure in the barrel on the up-hole side of the traveling valve. This condition may lead to gas locking of the rod pump since the pressure above the standing valve has equalized with the wellbore pressure below the standing valve at the rod pump inlet. As a result the gas/liquid combination becomes trapped and the continual heat of compression resulting in this operation can damage plunger seals in the downhole rod pump. This condition can occur at any rod pump inclination but is more likely to occur at high angle deviations since it requires that the conventional valve systems are fully operational; which, again, is dependent on the magnitude of the force due to gravity.
Using standard valve sub-systems in the down-hole rod pump when there is a high gas-volume ratio at the pump inlet and/or when the pump is landed at high deviations (greater than 45°), the valve sub-systems can remain off-seat for extended time periods and thereby allowing the tubing fluid level to equalize with the wellbore/reservoir pressure. In this condition, due to the depleted state of the reservoir, the free fluid surface in the tubing string will be at a level substantially below the surface with gas migrating through and occupying the portion of the tubing string above the free fluid surface. Due to the poor efficiency of the rod pump sub-systems, continuous high rate rod string cycling can lead to excessive heat accumulation in the upper region of the tubing string and ultimate failure of the polished valve rod stuffing box seal assemblies.
As the operating envelope for the traditionally configured rod pump has been expanded, there have been numerous accessories developed to maintain pumping efficiency in these challenging and/or deviated wellbores.
One prior art solution uses a spring biased Baird style standing valve whereby the standard ball and seat valve is biased closed using a spring. This spring applies a nominal preload to the uphole side of the ball which must be overcome by the wellbore pressure acting on the bottom area of the standing valve ball. This nominal spring force on the ball assists returning the ball to the seat following activation and will not reside off-seat during operation in high deviation wellbores. In order to initiate pumping with this sub-system in place the wellbore must have a net positive suction head in the annulus which will easily overcome the biasing spring force and off-seat the standing valve. In other words, the free surface of the fluid in the annulus must accumulate high enough above the pump intake such that the resulting hydrostatic pressure will off seat the standing valve.
In another example, a Baird snubber style traveling valve is similar in concept to the spring biased standing valve as this traveling valve is also spring biased. This valve also utilizes a spring to apply a pre-load to the top side of the ball to keep the valve firmly in place on the seat and minimize the times when the valve is caught off-seat and not isolating the top from the bottom side of the valve seat. This spring biasing in theory provides more utility to the sub-system within the rod pump for usage in highly deviated applications. These valves can be subject to tens of millions of cycles in 1 year of operating life. As such, the valves must be designed with these criteria in mind to evolve a successful rod pump sub-system.
Another prior art solution comprises a simple mechanical device with a reciprocating stem which when the pump is tapped (ie. traveling valve faced out on barrel cage bushing), the stem physically impacts and unseats the ball from the seat allowing pressure to equalize across the traveling valve in order to prevent gas locking.
Sliding top valve assemblies are known which temporarily relieve the hydrostatic pressure from the uphole side of the traveling valve to allow the pressure from below the traveling valve to readily equalize with the pressure above the traveling valve. This is of particular importance when there is a gas/volume ratio large enough to prevent the traveling valve from being unseated consistently. However, the effectiveness of the sliding top valve (also known as a hydrostatic relief valve) is very low in deviated wellbores. This device typically relies on gravity (weight of sliding valve) in order to close the valve and isolate the hydrostatic pressure in the tubing above. When the rod pump system is installed at any significant deviation from vertical, the effect of gravity acting along the valve center line is small and the weight of the valve rod and plunger assembly reciprocating through the inner diameter of the valve is such that it will tend to radially displace the valve and prevent it from traveling concentrically to engage the valve seat and isolate the hydrostatic pressure above the pump.
Therefore, there is a need in the art for rod pump systems which may be able to operate efficiently in high gas content scenarios and/or highly deviated wellbores.